Determination of formation pressure while drilling has been a challenge to the oil and gas industry. Knowledge of formation pore pressure variation ahead of the drill bit would allow a driller to control the mud weight and the overbalance pressure (i.e. the difference between the bottom hole mud pressure and the formation pore pressure) in an optimal way, reducing permeability damage without compromising the safety of drilling operations.
In many cases, however, accurate knowledge of the formation pressure is not so important as knowing whether it is above or below the downhole mud pressure. This information becomes crucially important when drilling through cover rock with very low permeability (e.g. shale or clay) separating high permeability formations, as the low permeability rock can sustain a high pore pressure gradient disguising a large differential between the pore pressures of the high permeability formations. If the mud pressure is not adjusted in time, such a differential can lead to a potentially hazardous kick or a circulation loss when the wellbore is extended to traverse the cover rock and re-enter high permeability formation.
Thus early indications of increases in pore pressure gradient (i.e. while drilling is restricted to the cover rock) could allow the driller to take appropriate action to reduce or eliminate the likelihood of kicks or circulation losses.
A conventional procedure for determining formation pore pressures is based on the hydrodynamic properties of the formation. In the procedure, a specially designed tool enters the well on a cable or wireline, engages with the formation forming the wall of the wellbore, and draws in an amount of pore fluid. The pore pressure can then be determined from the rate at which pore fluid enters the tool, taking due account of factors such as the pressure diffusivity within the formation, and the quality of filter cake created while drilling.
However, because of the common practice of drilling overbalance, the pore pressure near the wellbore tends to be higher than the formation pore pressure at a distance from the wellbore. Thus drilling is usually suspended for a period prior to testing to allow the near-wellbore pore pressure to recover (drilling in any event needs to be interrupted to allow the tool to enter the well on the wireline). Unfortunately, for low permeability formations, which take significant times to recover, the testing time then becomes unacceptably long.
Other conventional methods for formation pore pressure determination are based on empirical relationships between the formation pore pressure and porosity, in situ stresses, lithology and mineral composition of rock. These relationships are usually established by making correlations with log and seismic data from previously drilled wellbores, and may therefore be available only when the drilling of similar wells located nearby has been completed. For new wells in new formations, these methods do not provide reliable predictions of the formation pore pressure.